Scale is a persistent problem for the production of oil and gas. As brine, oil, and/or gas proceed from the formation to the surface, the pressure and temperature change and dissolved salts can precipitate. This is called “self-scaling.” If brine is injected into the formation to maintain pressure and sweep the oil to the producing wells, there will eventually be a commingling with the formation water, and additional salts may precipitate. This is called scaling from “incompatible waters.”
The most common oilfield scales are calcite (most stable polymorph of calcium carbonate or CaCO3), barite (BaSO4), celestite (SrSO4), anhydrite (anhydrous calcium sulfate or CaSO4), gypsum (CaSO4.2H2O), iron sulfide (FeS), and halite (rock salt of NaCl). “Exotic” scales such as calcium fluorite (halide mineral composed of calcium fluoride, CaF2), zinc sulfide (ZnS), and lead sulfide (PbS and PbS2) are sometimes found with high temperature/high pressure (HT/HP) wells.
Calcite deposition is generally a self-scaling process. The main driver for its formation is the loss of CO2 from the water to the gas phase(s) as pressure falls. This removes carbonic acid from the water phase, which had kept the basic calcite dissolved. Calcite solubility also decreases with increasing temperature (at constant CO2 partial pressure).
Halite scaling is also a self-scaling process. The drivers are falling temperature and evaporation. Halite solubility in water decreases with decreasing temperature, favoring halite dropout during the production of high total dissolved solids (TDS) brines to the surface. Falling pressure has a much smaller effect on decreasing halite solubility. Evaporative loss of liquid water is generally the result of gas breakout from under-saturated condensate and oil wells, as well as the expansion of gas in gas wells. This increase in water vapor can leave behind insufficient liquid water to maintain halite solubility in the co-produced brine phase. Halite self-scaling is found with both high-temperature and low-temperature wells [e.g., with 125 and 350° F. bottomhole temperature (BHT) gas/gas condensate wells].
Barite scales are generally the result of mixing incompatible waters. For example, seawater is often injected into offshore reservoirs for pressure maintenance. Seawater has high-sulfate content; formation waters often have high-barium contents. Mixing these waters results in barite deposition. If this mixing/precipitation occur within the reservoir far from a vertical wellbore, there will generally be little impact on the production of hydrocarbons, but scaling near or within the wellbore will have a significant impact on production. Mixing of incompatible waters within the sandpack of a hydraulically fractured well can also be detrimental to production. Furthermore, after the initial, large deposition of scale, this water continues to be saturated in barite and additional barite scale may continue to form in the wellbore as pressure and temperature fall.
Waterfloods combining ground waters with high calcium and high sulfate contents can deposit anhydrite or gypsum by much the same “incompatible waters” mechanism discussed for barite. However, calcium sulfate scale solubility, unlike that of barite scale, actually increases with decreasing temperature (until about 40° C.), although this can vary with NaCl concentration. This can decrease the likelihood of scale after the initial mixing deposition. The reversal in solubility falloff below 40° C. accounts for the gypsum scaling observed in surface equipment. This inverse temperature effect can result in the generation of anhydrite scale when injecting seawater. Anhydrite solubility falls as pressure falls. Data could not be found for gypsum solubility vs. pressure.
Iron sulfide scales are almost ubiquitous when hydrogen sulfide is produced—frequently the result of tubular corrosion in the presence of H2S. The chemistry is complicated; more than one iron sulfide phase can be present. The physical properties of the phases vary (sometimes dense, sometimes not), and the phase composition can change with time.
Scaling damage can be very rapid, and the effects quite expensive. In one North Sea well (Miller field), for example, production fell from 30,000 BPD to zero in just 24 hours because of scaling. The cost for cleaning out the single well and putting it back on production was approximately the same as the chemical costs to treat the entire field. While not all wells are susceptible to such momentous penalties for allowing scaling to begin, there is no question that scale prevention, formation, and remediation, have associated costs.
It is anticipated that oilfield scaling problems will continue to worsen and become more expensive. The new drivers are:                Tendency to longer tiebacks        Use of smart wells (integrity more critical)        More gas production (gas well formations tend to be more delicate)        Need to use greener chemicals        Increasing amounts of produced water.        
Scale remediation techniques must be quick and nondamaging to the wellbore, tubing, and the reservoir. Selecting the best scale-removal technique for a particular well depends on knowing the type and quantity of scale, its physical composition, and its texture.
If the scale is in the wellbore, it can be removed mechanically or dissolved chemically. Mechanical methods such a milling and jetting, are among the most successful methods of scale removal in tubulars. Chemical dissolution of certain wellbore scales is generally relatively inexpensive and can used when mechanical removal methods are ineffective or costly. However, all chemical and mechanical removal methods are reactive, not proactive. The use of inhibitors to prevent scaling to begin with would be a proactive method of dealing with the scaling problem, and thus is generally preferred over reactive technologies.
Scale precipitation can be avoided by chelating the scaling cation. This is costly because the reactions are “stoichiometric,” (e.g., one chelant molecule per one scaling cation). More effective however, are those chemicals that poison the growth of scale. These are “threshold” inhibitors, effectively inhibiting mineral scale growth at concentrations of 1,000 times less than a balanced stoichiometric ratio. Most inhibitors for inorganic scales are phosphorous compounds:                Inorganic polyphosphates        Organic phosphate esters        Organic phosphonates        Organic aminophosphates        Organic polymers        
A variety of scale inhibitors are well-known, and they are commercial available from many companies. Two chemical structures are shown in FIG. 1. These are used for the various carbonate and sulfate scales. Recently, the successful use of a nonphosphorus compound to inhibit halite precipitation has been described and field tested at moderate temperatures; more classical amine-based halite salt inhibitors are also available for halite inhibition.
The most frequently used method of delivering the inhibiting solution to the scaling brine has been the “inhibitor squeeze.” Here, an inhibitor-containing solution is forced (hence the “squeeze” name) into the formation, whereby the inhibitor then resides on the rock surface, slowly leaching back into the produced-water phase at or above the critical concentration needed to prevent scaling [the minimum inhibitor concentration or “MIC”].
It is intended that the released inhibitor protect the tubulars, as well as the near wellbore. It is required, obviously, that the inhibitor adsorb on the formation rock with sufficient capacity to provide “long-term” protection. It is also required that the inhibitor be relatively stable to thermal degradation under downhole conditions and be compatible with the particular brine system. It is also important that the inhibitor treatment not cause a significant permeability reduction and reduced production. These requirements are generally achievable, but again, one chemical does not necessarily fit all field situations.
Two types of inhibitor squeeze treatments are routinely carried out where the intention is either to adsorb the inhibitor onto the rock by a physico-chemical process—an “adsorption squeeze”—or to precipitate (or phase separate) the inhibitor within the formation pore space onto the rock surfaces—a “precipitation squeeze.”
Adsorption of inhibitors is thought to occur through electrostatic and van der Waals interactions between the inhibitor and formation minerals. The interaction may be described by an adsorption isotherm, which is a function of pH, temperature, and mineral substrate. The adsorption process for retaining inhibitor in the formation is most effective in sandstone formations. Treatment lifetimes are generally on the order of 3 to 6 months.
The “precipitation squeeze” process is based on the formation of an insoluble inhibitor/calcium salt. This is carried out by adjusting the calcium ion concentration, pH, and temperature of polymeric and phosphonate inhibitor solutions. Also used are calcium salts of phosphino-polycarboxylic acid or a polyacrylic acid scale inhibitor. The intent is to place more of the inhibitor per squeeze, extending the treatment lifetime. Normally, the precipitation squeeze treatment lifetime exceeds one year.
The engineering design of such adsorption and precipitation squeeze treatments into real-world multilayer formations is generally done with an appropriate piece of software. This simulator takes core flood data and computes the proper pre-flushes, inhibitor volumes, post flushes, and potential squeeze lifetime. Computer simulation of such chemistry is described in Shuler and Yuan.
A typical sequence of pumping steps involved in squeezing inhibitors is as follows:                Acid cleans the scale and debris out of the wellbore to “pickle” the tubing (this fluid should not be pushed into the formation).        “Spearhead” package (a demulsifier and/or a surfactant) increases the water wetness of the formation and/or improves injectivity.        A “preflush” fluid cleans hydrocarbon off rock surfaces and/or conditions the rock surfaces for adsorption of inhibitors.        Main scale-inhibitor treatment, which contains the inhibitor chemical, is normally in the concentration range of 2.5 to 20%.        An “overflush” fluid pushes the main scale inhibitor treatment to the desired depth in the formation away from the wellbore.        Shut-in or soak period (usually approximately 6 to 24 hours)—the pumping stops and the inhibitor adsorbs (phosphonate/polymers) or precipitates (polymers) onto the rock substrate.        The well is brought back to production, and the injection fluids backflow out of the well, followed by produced hydrocarbons.        
FIG. 2 illustrates a typical inhibitor return curve that shows the concentration of an inhibitor dissolved in the water phase as the well is brought back on production. A large amount of inhibitor returns immediately after turning on the well. This is nonadsorbed inhibitor or weakly adsorbed inhibitor. It is “wasted” in the sense that it is not available for use late in the life of the squeeze. This wasted inhibitor does not otherwise impose a serious financial burden on the treatment—the inhibitors can be the cheapest part of the inhibition treatment. The plateau (or slowly declining) portion of the return curve is the critical data that describe the effectiveness of the treatment. As long as the curve is above the MIC, the well is considered protected from scaling. Immediately below the MIC, scale formation may start to occur, and the scale inhibitor squeeze needs to be repeated.
The x-axis in FIG. 2 is given in terms of time (months). The lifetime parameter is more correctly volumes of water produced. Obviously, a high rate of water passing over a given amount of inhibitor will maintain the MIC for a shorter period of time than a low rate of water passing over the same amount of inhibitor.
Scale-inhibitor squeeze treatments can have undesirable side effects. These side effects include: process upsets, poor process and discharged water quality on initial flowback, extended cleanup period, deferred oil, and the potential for a permanent decrease in oil production combined with an increase in water production. The first three side effects listed are functions primarily of the oil, brine, and squeeze chemicals. Most of these problems can be avoided, or at least minimized, by prior laboratory testing. Deferred oil is an intrinsic problem in well intervention. However, production being maintained at higher rate for longer time than if scale formed and caused rapid decrease or stop in production will pay for the deferred oil.
Permanent decreases in production after inhibitor squeeze treatments are usually associated with pumping large amounts of water-based chemicals into water-sensitive zones, assuming an otherwise proper treatment design and the use of clean fluids. Clay swelling and in-situ emulsions are damage mechanisms; low pH-inhibitor solutions are often detrimental to clays, in particular to chlorites.
Handling the scale inhibition of water-sensitive reservoirs is not a solved problem. Several routes of addressing the issue are being investigated. One solution is the use of oil-soluble inhibitors. Another is the use of water-in-oil emulsion (“invert emulsions”), similar to the invert emulsions used for time-delayed acidization. A third solution is the use of a mutual solvent preflush; however, mutual solvents are designed to prevent emulsion formation. Here, the mutual solvent is the first chemical seen by the sensitive formation, and it is the last seen as the well is put back on production. Also used are “clay stabilizers” in the preflush. As of this writing, no single approach solves all problems.
Thus, what is needed in the art are better methods of scale inhibitor squeeze especially methods that minimize water retention in the reservoir.